ralph zarumba - aee · i am ralph zarumba and i am a director at navigant consulting, inc....

COMMONWEALTH OF PUERTO RICO

PUERTO RICO ENERGY COMMISSION

IN RE: THE PUERTO RICO ELECTRIC POWER AUTHORITY

No. CEPR-AP-2015-0001

PREP A Ex. 9.0

INITIAL RATE REVIEW SUBJECT: TESTIMONY IN SUPPORT OF PETITION

Direct Testimony of

RALPH ZARUMBA

Director, Navigant Consulting, Inc.

On behalf of the

Puerto Rico Electric Power Authority

May 27,2016

TABLE OF CONTENTS

No. CEPR- AP-2015-0001 PREP A Ex. 9.0

I. Introduction ......................................................................................................................... 1 A. Witness Identification ............................................................................................. 1 B. Summary of Direct Testimony ................................................................................ 1 C. Professional Background & Education ................................................................... 1 D. Additional Attachments .......................................................................................... 2

II. Description of the Marginal Cost of Service Study ............................................................ 2

III. Marginal Generation Service Costs .................................................................................... 3 A. Marginal Generation Capacity Costs ...................................................................... 3 B. Marginal (Generation) Energy Costs ...................................................................... 9

IV. Marginal Transmission Service Costs .............................................................................. 10

V. Marginal Distribution Costs .............................................................................................. 14

VI. Conclusion ........................................................................................................................ 19

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I. INTRODUCTION

2 A. Witness Identification

3 Q. Please state your name, title, employer, and business address.

4 A. I am Ralph Zarumba and I am a Director at Navigant Consulting, Inc. ("Navigant"), a

5 global business and advisory firm. My business address is 30 S. Wacker Drive,

6 Suite 3100, Chicago, Illinois 60606.

7 Q. Please state your name, title, employer, and business address.

8 A. I am Ralph Zarumba and I am a Director at Navigant Consulting, Inc. ("Navigant"), a

9 global business and advisory firm. My business address is 30 S. Wacker Drive,

10 f)\, 1 Suite 3100, Chicago, Illinois 60606. , L-'

11 B. Summary of Direct Testimony

12 Q. What are the purposes and subjects of your testimony?

13 A. I am testifYing in support of PREP A's Petition requesting that the Puerto Rico Energy

14 Commission (the "Commission") approve and establish new rates for PREP A. More

15 specifically, the purpose of my testimony is to present and support PREP A's Marginal

16 Cost of Service Study ("MCOSS"). The MCOSS was prepared properly and it meets the

17 objective(s) of identifYing the value of incremental costs required to serve new load.

18 c. Professional Background & Education

19 Q. Please state your professional background.

20 A. My resume, which reviews my education, professional qualifications, and experience

21 in detail, is attached is PREP A Exhibit ("Ex.") 4.01.

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D. Additional Attachments

No. CEPR- AP-2015-0001 PREPAEx. 9.0

Besides your resume, are there any additional attachments to your direct testimony?

Yes. The following additional exhibits are attachment to my direct testimony:

• PREP A Ex. 9.02: Distribution Investments

• PREP A Ex. 9.03: Transmission Investments

• PREP A Ex. 9.04: Marginal Cost of Service Study Results

DESCRIPTION OF THE MARGINAL COST OF SERVICE STUDY

Please describe what is an MCOSS?

In brief, an MCOSS provides estimates of the cost to provide the next unit of electric

service which is consumed by the customer. Mathematically, MCOSS is defined as the Q~

~ first derivative of the Total Cost Function in other words, the incremental change in

cost - when the quantity of service that is being measured is allowed to change by one.

Average Cost - which is calculated in the Embedded Cost of Service Study supported by

PREPA witnesses Ralph Zarumba and Eugene Granovsky, PREPA Ex. 8.0, is the total

cost divided by the total quantity produced. Economic theory tells us that marginal costs

are impmtant because they indicate to the utility and customers what cost impact an

increase or decrease in usage would have on the total revenue requirement of the utility.

For a complete discussion of the suppmting theory of marginal costs I recommend Alfred

Kahn's seminal work The Economics of Regulation.

Why is an MCOSS provided in this proceeding?

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Marginal costs were prepared for this filing to determine the additional cost to serve new

load, albeit during a timeframe when total electric demand is forecast to decline. 1 It also

provides data for appropriate price signals that may be employed in relation to demand-

side programs or third-party generation.

What are the components of the MCOSS?

The Marginal Cost of Service Study follows the functions of an electric utility. A

vertically integrated utility such as PREP A provides:

1. Generation Service. The generation function is analyzed as marginal generation

capacity costs and marginal energy costs;

2. Transmission Service. The transmission function only contains a capacity

component; and

3. Distribution Service. The distribution costs are analyzed by voltage level as well

as differentiated by demand related and customer related.

The following sections of my testimony walk through the calculation of marginal

costs associated each of these services.

MARGINAL GENERATION SERVICE COSTS

A. Marginal Generation Capacity Costs

Please define Marginal Generation Capacity Costs ("MGCC").

1 This marginal cost analysis was prepared using a load forecast that was available at the time. It is the same forecast that originally was used by outside experts (Siemens) in the pending "Integrated Resource Planning" or IRP case.

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MGCC are defmed as the cost to add new generating capacity to serve an additional

kilowatt ("kW") of load. The MGCC is the cost of maintaining electric generation ready

to serve load on demand regardless of the price or quantity of energy produced.

Please provide background on the environment for generation capacity in Puerto

Rico as reflected in the marginal cost analysis?

The environment for generation capacity in Puerto Rico can be defined as follows:

1. The Island is projected to have reduced load in the near and inte1mediate term.

2. Presently, PREP A's "firm2" reserve margin for generation resources effectively is

about 30 percent. This margin is consistent with reliability studies that identifY

the percent reserves needed to meet a Loss of Load Hours ("LOLH") expectation

of 4 hours per year, which is roughly equivalent to a Loss of Load Expectation

("LOLE") of 2 days per year. Inasmuch as island electric systems require a

higher reserve margin in order to maintain a reasonable level of reliability

PREP A's reserve margin, it significantly exceeds what is considered a "normal"

reserve margin in larger interconnected systems such as those located in

contiguous areas in North America.

2 Firm reserves is an approximation derived by subtracting the system peak load from the sum of the product of the installed capacity and availability of each generating unit. For PREP A, it is close to twice the size of the largest generating unit in its system (Aguirre 1& 2 450 MW). Actual minimum reserves could exceed this value. To achieve a LOLH of four hours or less, firm reserves as defined above must exceed 25 percent. Accordingly, a 30 percent reserve margin was deemed to be the minimum generating reserves needed to meet the 4-hour LOLH criterion.

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3. Inasmuch as generation investments are proposed in PREP A's Integrated

Resource Plan (IRP) these investments are being made for reasons other than to

serve load growth- they are being made in order to:

0 Achieve legally mandated environmental policies:

0 Maintain local reliability;

0 Integrate renewables, including distributed generation;

0 Improve efficiency; and

0 Reduce energy costs.

4. In the past several years, the use of Distributed Energy Resources ("DER") has

expanded in Puerto Rico. Examples of DER include cogeneration and rooftop

photovoltaic ("PV") generation. The DER technologies include those that

produce power intermittently, such as solar PV, which may require back-up

support from conventional generation to meet reliability targets.

How does the generation capacity environment impact the approach used for

estimating the MGCC adopted in your testimony?

The environment (see the factors above) impacts MGCC is in two ways. First, it impacts

the technology adopted as the marginal generation unit. Second, it impacts the timing of

when new generation is required, which in tum impacts estimated MGCC costs. The

environment reflected in the marginal cost analysis is one in which peak load is expected

to decline, which lessens the demand for new generating capacity. This lower demand, in

tum, decreases the marginal cost and capacity value of new generation.

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What technology was adopted in estimating MGCC?


Navigant analyzed all generation technologies, which could reasonably be used in Puerto

Rico and determined that a Wartsila model 18V50Sgg reciprocating engine generation

unit is appropriate for purposes of estimating MGCC. A reciprocating engine, the

Wmisila model18V50SG technology, was chosen rather than a simple-cycle combustion

turbine because it is the lowest cost alternative to supply capacity independent. of the

value of the energy output of a generating unit. The chm·acteristics of this technology are

summarized in the table below. Please note that PREP A is not recommending use of

reciprocating engines in the pending IRP case for reasons discussed therein. In brief,

different options are recommended in the IRP not only to provide capacity, but also to

provide energy, and this combination of these factors resulted in the selection of ~~

combined cycle options.

Installed Cost 2017$/kW-year $1,124

Annual Fixed O&M 2017$/kW-year $18.00

Economic Life Yem·s 20

110 Q. The installed cost of the Wartsila model18V50Sgg reciprocating engine generation

111 unit is a one-time cost. However, the generating unit provides service over several

112 years. What approach was used to recognize the cost of the asset over the 20 year

113 life?

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An accounting Fixed Charge Rate ("FCR") was calculated, which levelized the total cost

of the generating unit, including both capital recovery and Operations and Maintenance

("O&M") over the life of the asset. The assumptions used in the FCR calculation are

consistent with those used in the PREP A's IRP.

When will PREP A require new generation capacity to serve load?

No new generation capacity is needed to serve new load (as distinct from other purposes)

over the planning horizon, which is 20 years. New generation is proposed to comply

with legal requirements and for other non-capacity purposes, such as efficiency and

renewables integration, as noted earlier and which is addressed in the IRP case.

How have you adjusted the MGCC to reflect the distant need for generation

capacity for load?

One approach would be to state that because generation is not required for load in the

planning horizon, it has no value during this time frame. Although this is a reasonable

assumption given the PREP A load forecast employed in the marginal cost analysis, it

may be a misplaced interpretation of the estimated value of generating capacity. As an

alternative, I have adopted the "Discounted Peaker Approach." This approach is

appropriate for PREP A as it recognizes the future value of generation in an environment

where demand is forecast to decline over the next planning horizon.

Please describe the Discounted Peaker Approach.

The Discounted Peaker Approach recognizes that if a surplus of generation capacity

exists, the value of that capacity will be depressed. The Discounted Peak methodology

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quantifies the differences in prices over time. The Discounted Peaker calculation can be

stated as follows:

DP = PP·( 1

) (1 + r )"

where DP = Discounted Peak Price

PP = Peaker Price

r is the discount rate

n is the number of years until new capacity is required to serve new load (excluding

capacity constructed for energy savings)

What assumption was adopted for the number of years required until capacity is

required?

We assumed that capacity would be required in 20 years, which is the end of the planning

horizon. The assumption reflects an optimistic view of the capacity market and results in

the MGCC being potentially overstated because of the truncated nature of the analysis.

The results of the Discounted Peaker Approach are summarized in the table below:

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Peaker Price: Marginal Generation Capacity costs Using the Peak Approach

Annual Discount Rate

Number of Years Until New Capacity 1s Required to Serve New Load

Discount Factor

Discounted Peaker Marginal Cost

pp

r

n

( 6+1

r )' l DP = PP·(

1 l (1+r)"

Have the results been adjusted for voltage level?

$93.03

9.00%

20

17.84%

$ 16.60

Yes. The table below provides the MGCC by voltage level. The results are stated with

and without the reserve margin required for long-te1m planning purposes.

Generation N/A

$16.60 $21.58

• Transmission 3.00% $17.10 $22.23 Primary 8.31% $17.98 $23.37 Secondmy 10.16% $18.29 $23.77

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154 B. Marginal (Generation) Energy Costs

155 Q. How were Marginal (Generation) Energy Costs ("MEC") estimated?

156 A. We adopted the analyses performed by Siemens in the IRP process. Annual and seasonal

157 marginal energy costs appear in PREP A Ex. 9.04 attached to my testimony.

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Would you provide commentary on the results that are unique to Puerto Rico?

As noted above, a unique situation in Puerto Rico is that PREP A is an isolated system

and cannot rely upon neighboring utilities to provide reliability support. Therefore, as

previously stated, a higher reserve margin is required. Further, the level of spinning and

non-spinning operating reserve is higher than a. utility with a higher number of

interconnections with neighboring utility, which increases the level of fuel burn or

"Must-Run Generation". These factors are incorporated into the generation marginal cost

analysis via use of the 30 percent generation reserve margin cited above and marginal

energy costs that reflect the additional reserve requirements associated with operating as

an island. The production cost analysis conducted by Siemens and reported herein

includes adjustments for these additional reserves.

MARGINAL TRANSMISSION SERVICE COSTS

Please describe the economic nature of electric transmission systems?

Most electric transmission systems lines operate in a grid or network configuration; that

is, lines are configured in a manner such that the loss of a single line does not result in an

interruption of supply to load. The capability to provide continuous supply is commonly

refened to as meeting a single or double contingency criteria, where a contingency is

generally defined as a state under which there is loss of one or more transmission system

elements or generating units. Transmission systems are designed in this manner to

provide continuous supply to the system in case a specific component of the system fails

or is removed from service for maintenance. In some instances, transmission lines operate

radially, without contingency back-up. Radial transmission lines typically are lower

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voltage lines serving smaller load centers or located in remote areas on the system.

Transmission networks have unusual cost characteristics in that the cost to provide an

additional unit of output - the marginal costs is often significantly less than the average

cost of service due to the relatively large amount of investment required for non-load

related purposes such as system reliability and security.

What implications does the network nature of electric transmission systems have on

the type of investments required?

Transmission investments are made for a variety of reasons. The categories on these

investments include the following:

1. Investments that are required to ensure sufficient transmission capacity is

available under nmmal and contingency conditions to reliably serve new load,

commensurate with reliability criteria assigned to the interconnected generation

and transmission system. The capability of the transmission network to withstand

contingency events is essential if PREP A is to meet LOLH reliability targets.

2. Transmission investments intended to interconnect a generation unit to the

transmission grid;

3. Alleviation of intertie constraints that connect distant markets and provide the

opportunity for energy costs to be reduced (i.e., arbitrage opportunities), which

are expected to exceed the cost of the transmission interconnection;

4. Investments which are made in order to maintain or increase system reliability or

security and are umelated to increases in load; and,

5. Replacement of outdated, obsolete or worn-out equipment.

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How is Marginal Transmission Capacity Costs ("MGCC") defined?

The Marginal Transmission Capacity Cost is defined as the annual investment cost

incurred when an additional kW of load is served by the transmission network.

Therefore, it is necessary to isolate and remove project costs that are not associated with

load growth in the Transmission System Expansion and Integrated Resource Plans.

What time period is evaluated when estimating MGCC?

Because major load-driven transmission projects occur infrequently, it is necessary to

examme an extended time period in order to produce reasonable estimates of

transmission investments, commonly referred to as Long Run Marginal Cost After

discussions with PREP A Staff, the time period of 2015/16 through 2024/25 was chosen

to review transmission investments made to accommodate load growth. The total dollar

investment is determined in 2017, and measured against the change in Annual Peak

Coincident Electric Demand for the same time period. Coincident Peak Demand is used

because load diversity is generally accommodated in an electric transmission system and

the system must be capable of reliably serving load at the time of the electric system

peak.

What transmission investments does PREP A propose over the next ten years, and

what portion of these investments will be made to serve additional load?

The total transmission investment pmifolio for the next 10 years as of the marginal cost

analysis is $833 million (2017), and is presented in PREP A Ex. 9.03. The exhibit lists

and assigns each investment to one of the five investment categories described above.

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The following table summarizes 1 0-year transmission capital investments for each

category.

Category 10-Year Total

1 Capacity for Load Growth $0-

2 Interconnection of generation $0-

3 Alleviation Transmission Constraints $47,886,500

4 Reliability Improvements $464,033,877

Replacement of Deteriorated or Obsolete $321,301,020 5 Equipment

Total $833,221,397

The portion of these investments assigned to new load (Category 1) is zero. This

is an expected finding, as PREP A's Coincident Peak (CP) is projected to decline over the

next 10 years. All investments outlined in PREPA's IRP are required to connect new

generators, improve economic transfer capability and maintain reliability due to retiring

generation in the north, or to replace deteriorated and obsolete equipment. Capital

investments for reliability improvements include increases in line or substation capacity

that are needed to meet PREP A single or double contingency criteria, but otherwise not

required to serve new load. Several individual projects span multiple categories, such as

replacement of obsolete equipment with equipment that also improves transmission

system reliability. Where projects provide multiple benefits, the cost of the projects is

allocated to each category based on the relative benefits resulting from the investment.

For example, 40 percent of the 10-year cost of the single largest investment, Stmctural

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Reconstruction of 115kV Lines at $59 million, is allocated to reliability, the remaining 60

percent to replacement. Because none of the investments cited above is required for

growth in electrical demand, the marginal cost of transmission is zero.

MARGINAL DISTRIBUTION COSTS

Please describe an electric distribution system.

An Electric Distribution System delivers power received from the Transmission System

to the customer via equipment operating at primary and secondary voltages (provided that

the customer is not receiving service at a Transmission Voltage). Marginal Distribution

Costs are classified into two categories:

1. Marginal Distribution Capacity Costs. Marginal Distribution Capacity Costs

("MDCC") are defined as the cost to serve an additional KW of load on the

distribution system;

2. Marginal Distribution Customer Costs. Marginal Distribution Customer Costs

(MDCSC) are defined as the cost to serve another customer connected to the

system regardless of the level of usage they receive from the utility.

Please describe the approach used to estimate Marginal Distribution Capacity

Costs.

Distribution investments for the time period 2016 through 2025 were prepared by PREP A

in order to determine what fraction of those investments are associated with serving new

load as opposed to replacement of existing infrastructure or to maintain or improve

system reliability.

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Our estimates of MDCC were prepared in a mmmer similar to that of the Marginal

Transmission Capacity Cost Analysis. The investments associated with load growth over

a period of several years were divided by the level of load growth as measured by the

increase in new customers connected to the distribution system over the period 2016 to

2025. A key difference in the distribution analysis is that the denominator in the

calculation is the Non-Coincident Peak of new customer demand on PREPA's

distribution system as opposed to the Coincident Peak used to derive Marginal

transmission costs. The Non-Coincident Peak is used because distribution systems are

generally constructed as radial systems and, therefore, the peak load on individual lines

and substations may not coincide with the system peak. Unlike transmission, individual

lines and substations each must be capable of supplying their respective peak loads; that \\tv is, capacity requirements are set based on the non-coincident peak or NCP associated

with each new asset added to serve new customers, whereas transmission capacity

requirements are established based on the coincident peak of the interconnected network.

Thus, load diversity among distribution lines and substations as measured by coincident

peaks does not apply nor diminish the level of investment made by the utility.

Because of the expected decrease in load growth and the relatively small number

of new customers (approximately 7 thousand) that will be connected to PREPA's

distribution system over the next 10 years, Navigant estimated distribution NCP based on

the PREP A design standards for new load. For new customers, PREP A design standards

are based on a minimum residential connected demand of 5 kW. Hence, new distribution

capacity must meet current design standards as compared to average demand of about 2

kW for existing customers. Because some of the new customers will be larger

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commercial load, Navigant increased the average kW connected demand for new

customers to 8 kW. It excludes a customer cost component as new customers pay all

costs associated with line extensions and equipment needed to connect the new load.

The following process was undertaken to estimate Marginal Distribution Capacity

Costs:

1. Identification of Investments Associated With Load Growth - Similar to

transmission, the first step in this analysis was to identify the portion of proposed

distribution investments associated with load growth. This data was requested

from PREP A and information was provided for the period 2015 through 2025.

2. However, as previously determined in the Transmission Capacity Cost Analysis, a

negative change in Coincident Peak would lead to negative Marginal Distribution ~V

Capacity Costs. Therefore, for Marginal Distribution Capacity Costs, an alternate

approach was used by measuring the change in total new customers connected to

PREPA's distribution system from 2014 through 2025. Although the coincident

system peak is projected to decline, an increase in new customers in a given area

may result in investments in new distribution capacity in areas of the PREP A

system where growth is expected to occur. The increase in NCP demand was

estimated by multiplying the average NCP of 8kW per customer cited above by

the number of new customers over the years 2014 through 2025. MDCC was

then derived by dividing total load-related distribution capacity investments

between 2014 and 2025 by the increase in connected NCP demand. Load-related

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distribution investments include two years' actual amounts spent for 2014 and

2015, and forecast investments for 2016 through 2025.

What distribution investments does PREPA propose over the next 10 years, and

what portion of these investments will be made to serve additional load?

The total distribution investment portfolio for the next 10 years as of the marginal cost

analysis is $818 million ($2017), and is presented in PREPA Ex. 9.02. The exhibit lists

each distribution project or program investment to one of the five investment categories

outlined in the section on transmission. The following table summarizes 1 0-year

distribution capital investments for each category.

Category 10-Year Total

Capacity for Load Growth (in distribution 1 system elements)

1a Expansion $40,066,380

1b Improvement $126,317,703

2 Interconnection of Generation $0

3 Alleviation Transmission Constraints $0

4 Reliability Improvements $382,761,168

Replacement of Deteriorated or Obsolete $268,727,163 5 Equipment

Total $817,872,413

The majority of PREP A's distribution capital forecast is to replace deteriorated, obsolete

or inefficient equipment; or to construct new lines to improve reliability or operating

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flexibility. The amount of PREP A's 10-year distribution investment pmifolio assigned to

load growth (in distribution system elements) is $40.1 million. The $40.1 million is

based on the portion of PREP A's distribution capital forecast that is for the expansion of

its distribution lines and substations. Of this amount, about 50 percent or $20 million is

reimbursed to PREP A in the form of contributions in aid of construction and therefore,

excluded from the marginal cost calculation. The remainder of capacity investments

related to load growth is $126.3 million, all of which is for improving the performance of

the grid, and therefore excluded from Marginal Distribution Capacity Cost calculations.

When the $20.1 million is combined with load-related distribution capacity investments

of $8.3 million, net of customer contributions, total load-related capacity investments for

years 2014 through 2025 is $28.4 million. The majority of expansion projects that are

load growth-related are for new distribution substations, or for extension of overhead and

underground feeders.

What is the expected increase in total distribution NCP demand resulting from the

connection of new customers?

The total number of new customers between 2014 and 2025 is projected at 6,795, which

equates to an average annual growth of about 0.05 percent. When the 2014 average NCP

of 8 kW per customer is applied, the increase in connected NCP demand is about 55.8

MW, or 4.7 MW on an annual basis.

Please present MDCC based on the preceding analysis and values derived for

incremental capacity, NCP demand and incremental O&M associated with load-

related capital investments.

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337 A. The following table presents marginal costs based on actual values for 2014 and 2015,

338 and projected values for 2016 through 2025 stated in 2017 dollars. It includes

339 distribution O&M associated with load-related capital projects as described earlier in my

340 testimony.

Description Total

2014-2015 Actual Load-Related Capital Investment $8.3 MM

2016-2025 Forecast Load-Related Capital Investment $20.1 MM

Total 12-Year Load-Related Investment $28.4MM

2014-2025 Increase in Connected NCP Demand 55.8MW

Total12-Year Load-Related Investment $508.4/kW

Distribution Carrying Charge Rate 7.71%

Annual Marginal Distribution Capital Cost $39.3/kW-Yr

Annual Incremental O&M $0 /kW-Yr

Total Annual Marginal Distribution Capital Cost 39.3/kW-Yr

341

342 The result of the analysis produces an annual MDCC of $39.3/kW-Year. The

343 annual value is then allocated on a seasonal basis during on-peak and off-peak hours, and

344 combined with allocated Generation Marginal Capital Cost to produce Total Marginal

345 Capital Cost that appears in PREP A Ex. 9.04.

346 VI. CONCLUSION

347 Q. Please summarize the results of your analysis.

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PREPA Ex. 9.04 summarizes the results of the study, which are stated in FY 2017

dollars. I have stated the results for transmission, distribution primary and distribution

secondmy in an unbundled basis with MGCC, MTCC, and MDCC stated in dollars per

KW. The values that appear at the transmission, primary and secondary levels are

adjusted based on PREP A loss factors outlined below. The allocation of capacity costs

for both generation and distribution is based the percent hours within each time period.

For generation, LOLH typically is used to allocate capacity cost. However, the use of

LOLH would have resulted in the assignment of all generation capacity costs to the low

season due to the maintenance scheduling algorithm in the Promod production cost

model, so hours per period was deemed appropriate in lieu of LOLH. Because of this ~'l

adjustment, it may be appropriate to apply annual values for marginal costs that appear in

Ex. 9.04.

Loss Factors On-Peak Off-Peak On-Peak Off-Peak

Transmission 3.00% 3.00% 3.00% 3.00%

Primary 8.31% 8.31% 8.31% 8.31%

Secondary 10.16% 10.16% 10.16% 10.16%

Results also are presented on a KWH basis assuming an 80 percent load factor.

Is there any additional information you believe it is important to convey regarding

the marginal costs presented in your testimony?

Yes. The distribution component ofMCOSS presented in PREP A Ex. 9.02 is based on a

very small number of distribution facilities where local growth will cause substations or

lines to become overloaded. The chart below confirms that less 1 0 substations of

PREP A's 300+ substation are expected to experience overloads, some of which can be

Page 20 of21

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375 Q.

376 Yes.


addressed by minor upgrades such as load transfers to adjacent substations with lower

loads. Thus, unless load reduction initiatives or distributed generation, in sufficient

quantities, are located at these few locations, actual avoided distribution costs would be

zero. Fmiher, many substation experience peak loadings during late evening hours.

Thus, any solar-based distributed generation would not reduce peak distribution loads

that would enable capacity defenal.

PREPA Substation Loading Distribution

• • I I I 0~10% 10+20% 20-30% 30-40% 40-50% 50-60% 60-70% 70-80% 80-90% 90-100% 100%+

Percentage of Thermal Capacity

Does this complete your direct testimony?

Page 21 of21

ATTESTATION


Affiant, Ralph Zarumba, being first duly sworn, states the following:

The prepared pre-filed Direct Testimony and the Schedules and Exhibits attached thereto and the Schedules I am sponsoring constitute the direct testimony of Affiant in the above-styled case. Affiant states that he would give the answers set forth in the pre-filed Direct Testimony if asked the questions propounded therein at the time of the filing. Mfiant fmiher states that, to the best of his knowledge, his statements made are true and correct.

Affidavit No3t S&'J-.

Acknowledged and subscribed before me by Ralph Zarumba, of the personal circumstances above mentioned, in his capacity as a Director ofNavigant Consulting, Inc., who is personally known to me or whom I have identified by means of his driver's license number

(frr- ttt:voiS '2..fQs:l-1Jq~-~~~1 , in San Juan, Puerto Rico, this ZJ, th day of May 2016.

EXENTO PAGO ARANCEL LEY 47

-4 DE JUNIO DE 1982

ralph zarumba - aee · i am ralph zarumba and i am a director at navigant consulting, inc....

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